U.S. patent number 7,173,239 [Application Number 10/798,686] was granted by the patent office on 2007-02-06 for method and apparatus for downhole quantification of methane using near infrared spectroscopy.
This patent grant is currently assigned to Baker Hughes Incorporated. Invention is credited to Rocco DiFoggio.
United States Patent |
7,173,239 |
DiFoggio |
February 6, 2007 |
Method and apparatus for downhole quantification of methane using
near infrared spectroscopy
Abstract
The present invention describes a unique method and apparatus
for applying near-infrared spectroscopy to estimate weight percent
of methane in crude oil from which one can then infer gas-oil ratio
(GOR) of crude oils downhole in real time while collecting a fluid
sample. The correlation equations provided by this invention use
two wavelengths, one centered at 1670 and the other centered at
1682 nm. Both wavelengths are primarily sensitive to the methane
peak absorption. To significantly improve the fit,
non-spectroscopic parameters, such as temperature or pressure, can
be included in the correlation equation. Also, this invention can
be used to monitor sample cleanup by monitoring the increase in GOR
associated with cleanup as a fluid being pumped from the formation
transitions from mostly gas-free filtrate to mostly gas-containing
crude oil.
Inventors: |
DiFoggio; Rocco (Houston,
TX) |
Assignee: |
Baker Hughes Incorporated
(Houston, TX)
|
Family
ID: |
32965779 |
Appl.
No.: |
10/798,686 |
Filed: |
March 11, 2004 |
Prior Publication Data
|
|
|
|
Document
Identifier |
Publication Date |
|
US 20040178336 A1 |
Sep 16, 2004 |
|
Related U.S. Patent Documents
|
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
|
60454987 |
Mar 14, 2003 |
|
|
|
|
Current U.S.
Class: |
250/269.1;
250/255; 250/254; 250/268; 250/256; 250/253 |
Current CPC
Class: |
E21B
47/113 (20200501); G01N 21/359 (20130101); G01N
21/3577 (20130101); G01N 21/3504 (20130101) |
Current International
Class: |
G01V
5/08 (20060101) |
Field of
Search: |
;250/269.1,268,256,255,254,253 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
Primary Examiner: Gabor; Otilia
Assistant Examiner: Sung; Christine
Attorney, Agent or Firm: Madan, Mossman & Sriram,
P.C.
Parent Case Text
CROSS REFERENCE TO RELATED APPLICATIONS
This patent application claims priority from U.S. provisional
patent application No. 60/454,987 filed on Mar. 14, 2003 entitled
"A Method and Apparatus for Downhole Quantification of Methane
Using Near Infrared Spectroscopy" by Rocco DiFoggio.
Claims
What is claimed is:
1. A method for quantifying a weight percent methane of a fluid
downhole, comprising: obtaining the fluid downhole; measuring a
first optical density for the fluid at a first wavelength region
associated with a methane peak; measuring a second optical density
for the fluid at a second wavelength region associated with the
methane peak; and determining weight percent methane for the fluid
sample from the first and second measured optical densities.
2. The method of claim 1, wherein the first wavelength region has a
center wavelength of 1670 nanometers; and the second wavelength has
a center wavelength of 1682 nanometers.
3. The method of claim 1, further comprising: correlating weight
percent methane with optical absorbance at the first and second
wavelengths.
4. The method of claim 3, further comprising: correlating
pressure.
5. The method of claim 3, farther comprising: correlating
temperature.
6. The method of claim further comprising: determining a gas oil
ratio for the sample based on the weight percent methane.
7. The method of claim 1, further comprising: monitoring sample
cleanup based on a change in weight percent methane.
8. The method of claim 3, further comprising: correlating based on
synthetic mixtures of methane and dead crude oils.
9. The method of claim 1, further comprising: filtering an optical
density measurement with a 11 nm full width half maximum
filter.
10. The method of claim 1, wherein the first wavelength region has
a center wavelength of 1670 nanometers and the second wavelength
has a center wavelength of 1662 nanometers; correlating weight
percent methane, pressure and temperature with optical absorbance
at the first and second wavelength regions; and determining a gas
oil ratio based on the weight percent methane.
11. An apparatus for quantifying the weight percent of methane in a
wellbore environment, comprising: a tool for obtaining a fluid
downhole; a spectrometer for measuring a first optical density for
the fluid at a first wavelength region associated with a methane
peak and measuring a second optical density for the fluid at a
second wavelength region associated with the methane peak; and a
processor function for determining weight percent methane for the
fluid sample from the first and second measured optical
densities.
12. The apparatus of claim 11, wherein the first wavelength region
has a center wavelength of 1670 nanometers; and the second
wavelength has a center wavelength of 1682 nanometers.
13. The apparatus of claim 11, further comprising: a processor
function for correlating weight percent methane with optical
absorbance at the first and second wavelengths.
14. The apparatus of claim 13, the processor function further
comprising a function for correlating pressure.
15. The method of claim 3, the processor function further
comprising a function for correlating temperature.
16. The apparatus of claim 11 farther comprising: a processor
function for determining a gas oil ratio for the sample based on
the weight percent methane.
17. The apparatus of claim 11, further comprising: a processor
function for monitoring sample cleanup based on a change in weight
percent methane.
18. The apparatus of claim 13, the processor function further
comprising a function for correlating based on synthetic mixtures
of methane and dead crude oils.
19. The method of claim 11, further comprising: a filter for
filtering an optical density measurement with a 11 nm full width
half maximum filter.
20. The apparatus of claim 11, wherein the first wavelength region
has a center wavelength of 1670 nanometers and the second
wavelength has a center wavelength of 1682 nanometers, the
processor function further comprising a function for correlating
weight percent methane, pressure and temperature with optical
absorbance at the first and second wavelength regions and a
function for determining a gas oil ratio based on the weight
percent methane.
21. A computer readable medium in a computer containing executable
instructions that when executed by a computer perform a method for
quantifying the weight percent of methane in a wellbore
environment, comprising; obtaining a fluid downhole; measuring a
first optical density for the fluid at a first wavelength region
associated with a methane peak; measuring a second optical density
for the fluid at a second wavelength region associated with the
methane peak; and determining weight percent methane for the fluid
sample from the first and second measured optical densities.
22. The medium of claim 21, wherein the first wavelength region has
a center wavelength of 1670 nanometers; and the second wavelength
has a center wavelength of 1682 nanometers.
23. The medium of claim 21, further comprising: correlating weight
percent methane with optical absorbance at the first and second
wavelengths.
24. The medium of claim 23, further comprising: correlating
pressure.
25. The medium of claim 23, further comprising; correlating
temperature.
26. The medium of claim 21 further comprising: determining a gas
oil ratio for the sample based on the weight percent methane.
27. The medium of claim 21, further comprising: monitoring sample
cleanup based on a change in weight percent methane.
28. The medium of claim 23, further comprising: correlating based
on synthetic mixtures of methane and dead crude oils.
29. The medium of claim 21, further comprising: filtering an
optical density measurement with a 11 nm full width half maximum
filter.
30. The medium of claim 21, wherein the first wavelength region has
a center wavelength of 1670 nanometers and the second wavelength
has a center wavelength of 1682 nanometers; correlating weight
percent methane, pressure and temperature with optical absorbance
at the first and second wavelength regions; and determining a gas
oil ratio based on the weight percent methane.
Description
FIELD OF THE INVENTION
The invention relates generally to a method and apparatus for
quantifying the weight percentage of methane or the gas oil ratio
for a crude oil sample downhole by using the sample's absorbance at
two specially selected optical channels. The center wavelengths and
bandwidths of these channels were selected by a complex
simulation.
BACKGROUND OF THE INVENTION
In wellbore exploration, typically drilling mud such as oil-based
mud and synthetic-based mud are used. Filtrates from these muds
generally invade the hydrocarbon bearing formation through the
borehole wall. Thus, samples taken from the formation contain
drilling mud filtrate contamination. Thus, a sufficient volume of
fluid must pumped from the formation to reduce the filtrate
contamination in the sample to an acceptable level. Open-hole
sampling is an effective way to acquire representative formation
fluid samples. Formation fluid sample acquisition and analysis
allows determination of critical information for assessing the
economic value of reserves. In addition, optimal production
strategies can be designed to handle these complex fluids. In
openhole sampling, initially, the flow from the formation contains
a considerable quantity of filtrate, but as filtrate is drained
from the formation, the flow increasingly becomes richer in
formation fluid and less filtrate appears in the flow. That is, the
composition of fluid flowing from the formation progresses towards
a higher percentage of native formation fluid but a lower
percentage of filtrate as pumping continues and the filtrate that
had invaded the formation is depleted.
Thus, fluid being pumped from a wellbore undergoes a clean-up
process in which the purity of the sample increases over time as
filtrate is gradually removed from the formation so that less
filtrate appears in the sample. As the composition of the sampled
formation fluid changes, so do the optical and physical properties
of the sampled fluid, such as optical absorption, fluorescence,
refractive index, density, and viscosity. A number of different
measurements are used to determine various optical and physical
properties of a fluid downhole in real time. Measuring these
properties of the fluid therefore provides insight into a sample's
purity.
When extracting fluids from a formation, it is desirable to
quantify the cleanup progress, that is, the degree contamination
from filtrate in the formation fluid sample in real time. If it is
known that there is too much filtrate contamination in the sample
(e.g., more than about 10% filtrate), then there is little reason
to collect a formation fluid sample in a sample tank. One should
wait until the contamination level drops to an acceptable level. On
the other hand, if by pumping for a relatively long time, it is
possible to achieve an only slightly better filtrate contamination
level, an operator may end up wasting very expensive rig time and
also risks the very costly possibility of allowing a tool to become
stuck in the wellbore.
When pumping first begins, the fluid being pumped contains a large
amount of mud filtrate contamination but the fluid filtrate
percentage is decreasing at the fastest rate. This process of
decreasing fluid filtrate contamination is referred to as sample
clean up. Later, the pumped fluid contains less contamination but
the fluid filtrate percentage decreases at a slower rate. One way
to monitor cleanup is to monitor the increase in gas oil ratio
(GOR) as pumping continues and the flow from the formation cleans
up from mostly gas-free oil-based mud filtrate and to mostly
gas-containing oil. Oil companies are also very interested in
knowing the GOR of the crude oils that they find downhole
independent of using GOR as a cleanup monitor. Thus, there is a
need for a method and apparatus for determining GOR in real time
downhole.
SUMMARY OF THE INVENTION
This method and apparatus of the present invention utilizes
spectroscopy to estimate the weight fraction of methane and the
corresponding Gas Oil Ratio (GOR) for a methane-in-crude-oil
mixture. A method and apparatus are provided to determine the gas
oil ratio from the weight fraction of methane, which is determined
spectroscopically. The present invention provides a method and
apparatus for optical analysis of formation fluids using near
infrared (NIR) illumination, which provides a measurement of
optical absorbance at wavelengths of 1670 nanometers and 1682
nanometers. The methods of this invention correlate the absorption
at these two wavelengths to the weight percent methane and GOR. A
borehole apparatus for measuring the spectral absorbance of
formation fluids includes a testing region, a conduit for directing
formation fluid into the testing region, a light source emitting at
least near infrared rays into the testing region, a spectral
detector optically coupled to the testing region, and a processor
coupled to the spectral detector. The testing region is an
optically transparent cell or chamber which is located between the
light source and the spectral detector such that light directed
from the light source to the spectral detector is passes through
formation fluid. The spectral detector is in one example is a
filter spectrograph, which measures the spectrum of the light which
has been transmitted through the formation fluid in the testing
region.
The present invention provides a method and apparatus for
quantifying methane and GOR downhole using a complex simulation and
regression selection process to obtain specially selected optical
filters having particular selected center wavelengths and
bandpasses (11 nm full width half maximum FWHM) to quantify the
weight percentage of methane or the GOR for a crude oil sample in
real time downhole. Specifically, the invention is a method of
determining weight percent methane and GOR for formation fluid
samples being pumped from a formation surrounding a wellbore by a
wireline tool or a monitoring-while-drilling formation tester to
obtain weight percent methane and to estimate GOR for a formation
fluid sample.
Unlike Mullins U.S. Pat. No. 6,476,384 (Mullins '384), which
describes a method for determining GOR based on two wavelengths,
the first located near a methane-gas spectral peak and the second
located near a liquid-hydrocarbon spectral peak (representing oil),
the present invention uses two wavelengths that are both near a
single spectral peak for methane (i.e., two regions of the same
methane peak). Also, unlike Mullins '384, which based its spectral
GOR determination equations on a training set of binary mixtures of
n-heptane (representing oil) and methane, the present invention
bases its spectral GOR equations on synthetic mixtures of methane
and dead crude oils. A dead crude oil is one for which little or no
gas remains in the crude oil because it was not stored under
pressure and therefore the gas in it was released. Unlike heptane,
which is visibly clear, real crude oils have considerable amounts
of dark-colored asphaltenes. The tails of the optical absorption
peaks of asphaltenes usually produce the equivalent of a baseline
offset and some baseline tilt in the long-wavelength region (1620
1780 nm) that includes both the methane and liquid hydrocarbon
peaks. Also, the liquid hydrocarbon peak is more complicated (has
features associated with aromatics, saturates, etc.) for the case
of a mixture of hundreds of hydrocarbons (dead crude oils) than for
the case of a single pure solvent (the saturate, n-heptane). For
both reasons, in contrast to Mullins '384, the present invention
uses stock tank crude oils rather than n-heptane to represent
downhole crude oil in the modeling for GOR or weight percent
methane.
BRIEF DESCRIPTION OF THE FIGURES
Other objects and advantages of the invention will become apparent
upon reading the following detailed description and upon reference
to the accompanying drawings in which:
FIG. 1 is a schematic diagram of a exemplary embodiment of the
present invention deployed on a wireline in a downhole
environment;
FIG. 2 is a schematic diagram of an exemplary embodiment of the
present invention deployed on a drill string in a monitoring while
drilling environment;
FIG. 3 is a schematic diagram of a exemplary embodiment of the
present invention deployed on a flexible tubing in a downhole
environment;
FIG. 4 is a schematic diagram of an exemplary embodiment of the
present invention as deployed in a wireline downhole environment
showing a cross section of a wireline formation tester tool;
FIG. 5 is a diagram of the Fluid Characterization Module;
FIG. 6 is illustration of a regression analysis over two
wavelengths and temperature for weight percent methane and GOR;
and
FIG. 7 illustrates three spectra of methane at various temperatures
and pressures and one representative crude oil spectrum.
FIG. 8 illustrates a flow chart of functions performed by the
present invention.
DETAILED DESCRIPTION OF AN EXEMPLARY EMBODIMENT
FIG. 1 is a schematic diagram of an exemplary embodiment of the
present invention deployed on a wireline in a downhole environment.
As shown in FIG. 1, a downhole tool 10 containing a optical
analyzer 410 of the present invention is deployed in a borehole 14.
The borehole is formed in formation 16. Tool 10 is deployed via a
wireline 12. Data from the tool 10 is communicated to the surface
to a computer processor 20 with memory inside of an intelligent
completion system 30. FIG. 2 is a schematic diagram of a exemplary
embodiment of the present invention deployed on a drill string 15
in a monitoring while drilling environment. FIG. 3 is a schematic
diagram of an exemplary embodiment of the present invention
deployed on a flexible tubing 13 in a downhole environment.
FIG. 4 is a schematic diagram of an exemplary embodiment of the
present invention as deployed from a wireline downhole environment
showing a cross section of a wireline formation tester tool. As
shown in FIG. 4, the tool 416 is deployed in a borehole 420 filled
with borehole fluid. The tool 416 is positioned in the borehole by
backup arms 416. A packer with a snorkel 418 contacts the borehole
wall for extracting formation fluid from the formation 414.
Wellbore fluid can be drawn from the wellbore also by not extending
the snorkel to the wall and pumping fluid from the wellbore instead
of the formation. Tool 416 contains optical analyzer 410, shown in
FIG. 5, disposed in flow line 426. The optical analyzer response is
monitored to determine weight percent methane and GOR of the
formation fluid. Pump 412 pumps formation fluid from formation 414
into flow line 426. Formation fluid travels through flow line 424
into valve 420, which directs the formation fluid to line 422 to
save the fluid in sample tanks or to line 418 where the formation
fluid exits to the borehole.
FIG. 5 illustrates a schematic representation for a downhole fluid
characterization module, as, for example, the Baker Atlas
SampleViews.sup.SM tool. A light source 101 (e.g. tungsten light
bulb) emits light toward a formation or wellbore sample 110. Light
from light source 101 is collimated by a collimating lens device
103 lying between the light source and the sample 110. The
collimated light 111 is incident generally perpendicular to a first
sapphire window 301 adjacent sample 110. Sapphire windows 301 and
303 lie generally perpendicular to the collimated beam of light and
are separated by a gap or channel 304 enabling a fluid sample 110
to flow between them. The flow channel 304 can be flow line 426.
Reflected and fluoresced light can be monitored over time in the
spectrometer 105 and processor/electronics/memory 106 comprising a
central processing unit, control circuitry and memory (not shown)
to determine sample properties such as weight percent methane and
GOR. The exemplary tool shown in FIG. 5 is fitted with ultraviolet,
near infrared, mid-infrared (UV/NIR/MIR) wavelength light sources
112, which can be turned on when the tungsten light source 101 is
turned off. The same spectrometer, comprising single wavelength
filters 108 over spectrometer photodiodes, enables collecting the
crude oil spectra for light transmitted, reflected or fluoresced in
the UV, NIR, MIR bands associated the sample in flow channel
304.
The present invention provides a multiple channel spectrometer, in
the current example comprising 24 channels of visible, near
infrared (NIR) and mid infrared (MIR) light, which are shown
through the sample 110 and filtered out into separate wavelength
bands.
Two filters center wavelengths are carefully selected to be at 1670
nm and 1682 nm and to have bandpasses of 11 nm full width half
maximum (FWHM). These two wavelengths were selected based on a
complex simulation in which spectra of methane at various pressures
and temperatures were added in random amounts to the spectra of 10
randomly chosen crude oil spectra from a data base of 500 spectra
of diverse crude oil samples from around the world. The laboratory
spectra were degraded to 11 nm resolution to approximate what is
currently the best resolution of commercially available
long-wavelength high temperature optical filters that are suitable
for downhole use. Various step-forward and step-backward
regressions with substitution were performed on the simulated
mixtures over a wavelength region of 1500 1900 nm to determine the
best-correlating center wavelengths, which turned out to be 1670 nm
and 1682 nm, and their corresponding correlation equations.
Temperature and pressure, which are non-optical parameters, were
also used in the regressions along with the selected wavelengths to
obtain the equation for weight fraction of methane.
According to the invention, a borehole apparatus for measuring the
spectral peaks of a methane region includes a testing region, a
conduit for directing formation fluid into the testing region, a
light source emitting at least near infrared rays into the testing
region, a spectral detector optically coupled to the testing
region, and a processor coupled to the spectral detector. The
testing region is a transparent cell or chamber, which is located
between the light source and the spectral detector such that light
directed from the light source to the spectral detector is
interrupted by formation fluid. The spectral detector is preferably
a spectrometer, which measures the spectrum of the light, which has
been transmitted through the formation fluid in the testing
region.
As shown in FIG. 6, the optimal center wavelengths 1670 nm and 1682
nm were derived from a regression analysis on a much broader
wavelength region of 1500 nm 1900 nm. FIG. 6 illustrates the
equations for calculation of methane weight and GOR from the
selected channel measurements. FIG. 6 also shows empirical
correlations developed for the weight fraction of methane in
mixtures of methane and crude oil in the current example of the
invention. The correlation equation gives the weight fraction of
methane as a function of the mixture absorbance at two wavelengths
(1670 nm and 1682 nm) and temperature. FIG. 6 also illustrates
empirical correlations associated with the present invention and
developed for the density of methane as a function of pressure and
temperature and for the optical absorption per millimeter of
methane as a function of methane density and wavenumber (a
wavenumber is 10,000,000/wavelength expressed in nanometers)
regardless of pressure and temperature.
As shown in FIG. 6, the equation for correlating weight fraction
methane in mixtures of crude oil and methane to optical absorbance
and temperature are illustrated.
The form of the equation for methane weight fraction in the present
invention is that of an offset constant, B0, plus a first constant,
B1, times a first variable, Var1, plus a second constant, B2, times
a second variable, Var2, and so on to an N-th constant and
variable. METHWTF=Methane Weight
Fraction=B0+B1*Var1+B2*Var2+B3*Var3+B4*Var4 . . . BN*VarN
The following is a first example of a Regression Summary for
Dependent Variable: METHWTF R=0.98093203 R.sup.20.96222765 Adjusted
R.sup.2 0.96151158 F(4,211)=1343.8 p<0.0000 Std.Error of
estimate: 0.04992
TABLE-US-00001 B 0.065139686 = B0 = Intercept Var1 = SQ70_82
11.17561047 = B1 Var2 = TEMP_C 0.000869088 = B2 Var3 = SRSA1682
-2.661667658 = B3 Var4 = SRSA1670 2.63244987 = B4 Where: SQ70_82 =
SQUARE (Absorbance_at_1670_nm - Absorbance_at_1682_nm SRSA1670 =
SQRT (Absorbance_at_1670_nm SRSA1682 = SQRT (Absorbance_at_1682_nm
TEMP_C = Temperature in Degrees Centigrade TEMP_SQR = Square of
Temperatire in Degrees C.
The following is a second example of a Regression Summary for
Dependent Variable: METHWT R=0.98190316 R.sup.2=0.96413381 Adjusted
R.sup.2=0.96327986 F(5,210)=1129.0 p<0.0000 Std.Error of
estimate: 0.04876
TABLE-US-00002 B 0.031427753 = B0 = Intercept Var1 = SRSA1670
2.531111433 = B1 Var2 = SRSA1682 -2.557658783 = B2 Var3 = SQ70_82
11.91350402 = B3 Var4 = TEMP_C 0.0019 = B4 Var5 = TEMP_SQR -6.2E-06
= B5
Baseline offset refers to a simultaneous and equal increase in the
absorbance of whatever optical channels are being monitored. In
this example, it would refer to an increase in the absorbance at
both 1670 nm and 1682 nm by the same amount. Inspection of the
first and second example equations shows that these equations have
little sensitivity to baseline offset. This fact is one of the
benefits of basing one's model on asphaltene-containing crude oils
rather than on clear solvents. Doing so provides insensitivity to
the presence of asphaltenes, which, to first order, simply appears
as a baseline offset over the narrow wavelength region of 1670 nm
to 1682 nm. The degree of this baseline offset depends upon the
type of asphaltenes and upon their concentration.
The dominant term of the first equation is the square of the
difference (the slope) between 1670 nm and 1682 nm. A slope is
completely invariant to baseline offset. Also, taken together, the
third and fourth terms are approximately equal to the slope between
1670 nm and 1682 nm on a plot of the square root of absorbance
versus wavelength and so have low sensitivity to baseline offset.
In like manner, the second equation is very insensitive to baseline
offset and thus insensitive to the presence of asphaltenes, which
inevitably are found in any real crude oil.
We developed the following empirical equation (Adjusted
R.sup.2=0.99911359) for the density of methane [g/cc] as a function
of pressure and temperature from 100 30,000 psia and 75 200.degree.
C.
TABLE-US-00003 B 2.771E-03 = Intercept P 2.480E-05 P.sup.2
-1.120E-09 for Pressure in psi P.sup.3 1.808E-14 T.sup.2 -1.308E-07
for Temperature in C. (P/T) 1.455E-03 (P/T).sup.2 -4.922E-06
(P/T).sup.3 5.934E-09
We also developed the following empirical equation (Adjusted
R.sup.2=0.94145159) for optical absorbance per millimeter of
methane as function of density and wavelength over 1668 1684 nm,
100 30,000 psia, and 75 200 C, assuming a bandpass of 11 nm
FWHM.
TABLE-US-00004 B -19.9061 = Intercept Methane Density 0.7747 for
Density in g/cc WaveNumber/1000 3.3326
where, Wavenumber=10,000,000/.lamda.[nm] The following definitions
and equations let us relate GOR to Weight Fraction of Methane,
f.sub.M, and Stock Tank Oil Density, .rho..sub.O. 1 bbl=0.159
m.sup.3=5.615 cu ft=42 U.S. gal 1 Standard Cubic Foot (SCF) of
Methane Gas at the standard conditions of 14.7 psia and 60.degree.
F. is 0.042358 lbs=19.21327 grams. So, the density of Methane at
60.degree. F. and 14.7 psia is 0.0006787 gr/cc=0.042358
lbm/ft.sup.3. The Gas Oil Ratio is defined as
GOR=V.sub.Methane[SCF]/V.sub.Oil[bbls] so GOR={W.sub.M/(19.21
g/SCF)}/{(W.sub.O/.rho..sub.O)(1 bbl/158 983 cc)} Let
f.sub.M=Weight Fraction of Methane, and let the subscripts
V=Volume, W=Weight, .rho.=Density, M=Methane, and O=Oil. Then:
GOR=8274.62 .rho..sub.O/(1/f.sub.M-1)
f.sub.M=W.sub.M/(W.sub.M+W.sub.O)=.rho..sub.MV.sub.M/(.rho..sub.MV.sub.M+-
.rho..sub.OV.sub.O) or W.sub.O=W.sub.M/(1/f.sub.M-1). Rearranging
the equation for GOR we obtain:
f.sub.M=1/(1+8274.62*.rho..sub.O/GOR) where W.sub.G and W.sub.O are
in grams, .rho..sub.O is in g/cc, and f.sub.M=Wt. Frac. of
Methane
FIG. 7 shows three spectra of methane at various pressures and
temperatures and the positions of the 1670 nm and 1682 nm channels
relative to the methane peak. The higher the mass density [g/cc] of
the methane the taller the methane peak. Note that the 1670 nm
channel is almost at the pinnacle of the methane peak whereas the
1682 nm channel is slightly to the right of the pinnacle on the
right shoulder of the methane peak.
Also shown is a representative crude oil spectrum. The rising left
edge of this spectrum is the asphaltene peak of the crude oil. The
liquid hydrocarbon peak of the crude oil is near 1740 nm. In a
mixture of methane and crude oil, the methane peak will appear to
sit on top of the right-hand tail of the asphaltene peak. That is
why it is important that the weight-percent-methane model be
insensitive to baseline offset.
Turning now to FIG. 8, a diagram of some of the functions performed
in the tool and associated processor functions in present example
of the invention is illustrated. In block 810 in the present
example of the invention a training set of high-resolution
absorption spectra of synthetic mixtures of methane and dead crude
oils is prepared. In block 812 in the present example of the
invention these high-resolution spectra are degraded to 11 nm FWHM
resolution corresponding to best available high-temperature
filters. In block 814 in the present example of the invention the
best correlating center wavelengths (1670 nm and 1682 nm) to weight
fraction of methane in crude oils are determined. In block 816 in
the present example of the invention the correlation equations that
use these best correlating wavelengths and/or temperature and/or
pressure are determined. In block 818 in the present example of the
invention a first absorbance of a downhole fluid at a first
wave-length region (1670 nm) associated with a methane peak is
obtained. In block 820 in the present example of the invention a
second absorbance of a downhole fluid at a second wave-length
region (1682 nm) associated with a methane peak is obtained. In
block 822 in the present example of the invention a weight fraction
of methane and corresponding GOR for the downhole fluid are
determined using the earlier derived correlation equation and the
sample cleanup can be also monitored based on a change in weight
percent methane or GOR.
The present invention has been described as method and apparatus
operating in a downhole environment in the preferred embodiment,
however, the present invention may also be embodied as a set of
instructions on a computer readable medium, comprising ROM, RAM, CD
ROM, Flash or any other computer readable medium, now known or
unknown that when executed cause a computer to implement the method
of the present invention. While a preferred embodiment of the
invention has been shown by the above invention, it is for purposes
of example only and not intended to limit the scope of the
invention, which is defined by the following claims.
* * * * *